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Flow Assurance: A π3 Discipline
Lloyd D. Brown, Conoco, Inc.

Copyright 2002, Offshore Technology Conference
This paper was prepared for presentation at the 2002 Offshore Technology Conference held in
Houston, Texas U.S.A., 6–9 May 2002.
This paper was selected for presentation by the OTC Program Committee following review of
information contained in an abstract submitted by the author(s). Contents of the paper, as
presented, have not been reviewed by the Offshore Technology Conference and are subject to
correction by the author(s). The material, as presented, does not necessarily reflect any
position of the Offshore Technology Conference or its officers. Electronic reproduction,
distribution, or storage of any part of this paper for commercial purposes without the written
consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print
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presented.

Abstract
Flow assurance is a deepwater challenge in our industry. Flow
assurance is successful operations that generate a reliable,
manageable, and profitable flow of fluids from the reservoir to
the sales point. Flow assurance is a critical function for
economic production in deepwater. The significant limits of
access to seafloor infrastructure in deepwater (> 1200 ft. water
depth) transforms operational problems in shallow water
production into economic, life limiting events for deepwater
assets. Significant operations, project, installation, fabrication,
engineering, science, and business efforts are focusing on
developing and implementing solutions for successful
production in deepwater assets. These efforts are identifying
that integration of the proficiencies of these separate
disciplines is critical to successful implementation of cost
effective, production reliability.
Flow assurance is transformed into a cross-functional, team
discipline that drives a holistic, integrated perspective of asset
development from project conception to production operations
and from reservoir to beyond the sales point. The flow
assurance discipline is demanding due to its diverse nature. It
requires a simple, success strategy. This strategy can be
defined by the components Proficiency, Integration,
Implementation, and Improvement or simply PI3 (π3).
Introduction
Flow assurance in the oil and gas industry has taken on new
dimensions as the industry has progressed into deeper water,
the access to subsea infrastructure becomes increasingly
limited, and as accelerated project schedules are required to
meet the economic hurdles required in an expanding corporate
portfolio. A flow assurance discipline assists our respective
corporations, projects, and operations with insuring the design

and operations of our assets can produce a profitable, flow
stream of fluids from the reservoir to the market in a manner
that meets the assets economic, safety, health, and
environmental expectations. The purpose of this paper is to
review the issues addressed by the flow assurance. Integration
of discipline interfaces will be recognized as a key success
factor to the diverse and comprehensive responsibilities of the
flow assurance discipline. The guidance provided by the π3
strategy and the focus it provides will be discussed.
Flow Assurance
What is flow assurance? Typically, flow assurance is
discussed in terms of the science of the characteristics of
production fluids and the engineering of solutions to the
challenges those characteristics. The science of and
engineering solutions for hydrates, paraffin, asphaltenes, scale,
fluid transport, and corrosion have been discussed numerous
times in the literature. The fundamental understanding and the
computational simulators that these fundamental
understandings have developed are allowing significant
progress to be made in engineering discussion and design.
Science is fundamental to simulation, simulation is
fundamental to engineering, and engineering is fundamental to
execution and operation. The learnings we have developed
are supported by collaborations and independent studies
between the technical experts funded in competitive times
within each of our budgets.
However, the number of operational issues with newly,
engineered solutions in deepwater should give us pause for
concern. Our industry’s learning curve in deepwater is not
much better than our historical learning curve when we moved
offshore to shallow water. How many of our deepwater assets
are living up to their corporate sanctioned economics? What
equivalent barrel of oil produced represents the economic
break point for the asset? What is the sensitivity of achieving
that equivalent barrel of production to flow assurance? How
many of us have had to assist with the ‘patches’ that make
flow assurance solutions work? Where was the ‘ball’ dropped
in executing the operations solution? Has our perspective
changed to support operations success?
In this paper, the definition of flow assurance will be unique
from the independent, scientific or engineering disciplines that

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L.D. BROWN

we have used in the past. Flow assurance is successful
operations that generate a reliable, manageable, and profitable
flow of fluids from the reservoir to the sales point. The flow
assurance discipline that enables these operations is an
integration of disciplines, from operations to engineering to
business to science. It requires the involvment of all the
people involved in the value chain of an asset from operations
support to contractor to the scientist. The flow assurance
discipline drives a new perspective, a new focus in our
approach to reliable production operations. Its vision goes
from reservoir to sales, from concept design to operations.
The flow assurance discipline has a number of challenges. In
this paper the technical and implementation management
challenges will be reviewed. The integration of the
proficiencies found within the people found within the
organizations to the purpose of successful implemenation and
improvement of flow assurance is the π3 strategy. The targets
are value effective production, no surprises during operations,
and executing improvement.
Technical Challenges
The technical components of flow assurance provide
significant new tools with which to engineer solutions. These
and the unresolved challenges will be reviewed to appreciate
some of the flow assurance interface issues that exist.
Fluid Characterization
The fluid characteristics of the reservoir fluid(s) are
fundamental to every aspect of flow assurance. The
commercial quality, the pressure-volume-temperature
characteristics, the SARA, the PNA, water chemistry, and
drilling mud characteristics are important information that is
required by the many disciplines supporting an asset
development. Every project generally works against a fluid
model, either an equation of state (EOS) or a tradition fluid
model such as black oil. Whitson’s and Brule’s recently
published SPE monograph does an elegant job of covering the
fundamentals for fluid characterization.1 PVT simulators that
allow non-linear ‘tuning’ against experimental PVT data and
can export the ‘tuned’ model to other reservoir, well, process,
and transport simulators provide the best opportunity to utilize
a consistent fluid model from reservoir through process and
export.
Consistent fluid characterization and fluid models from
reservoir to process are imperative to minimize the inevitable
surprises in operations. The fewer the number of high quality
reservoir samples, the more difficult it is to determine the
economic risk boundaries within which our reservoir, our
wells, our risers and flow lines, and our process must operate.
Designing against what one assumes without proper fluid
characterization can have significant impact on design and
operations of an offshore asset. An increasing use of studies
that assess the PVT quality and integrate the fluid
characterization with the reservoir understanding can be found
in a number of asset developments.

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However, the range of design flexibility for a project narrows
quickly after project sanction. The value of high quality,
appraisal fluids to characterize prior to project sanction must
be recognized during the asset discovery and appraisal
process. The alternative is building a wide range of flexibility
into the operations design. Collecting high quality MPSR or
MRSC fluid samples, then checking their quality during the
drilling operation is a π3 success within Conoco’s DW GOM
business unit. It was an effort that spaned science to drilling
operations considering the value of the information and
supported by exploration management. We are repeatedly
collecting appraisal fluid with less than 5% mud
contamination. This success has allowed us the confidence
needed to establish a design basis on sound PVT analysis and
models that impact reservoir to water chemistry modeling.
The value of these efforts is reflected in reducing the cost of
flexibility within our reservoir, facility, and operations design.
It is imperative that everyone involved recognize the value of
understanding the cycle time for resolving fluid data within
the time cycle available to a project’s decision schedule.
Analysis for Saturates, Aromatics, Resins, Asphaltenes, and
Napthenes by SARA, PNA, and/or PARA analysis, High
Temperature Gas Chromotagraphy (HTGC) analysis for ncarbon fractions, and Wax Appearance Temperature (WAT)
by cross polarized microscopy are becoming industry standard
fluid analysis for deepwater asset development. In addition,
we are recognizing that details such as constant composition
expansion (CCE) experiments at multiple temperatures, C7+
characterization, pipeline viscosity at multiple temperatures,
and asphaltene flocculation/filter tests are easily pre-scheduled
during initial PVT analysis, bring fast track closure to fluid
uncertainties, and can be incorporated into the demanding
PVT anlysis que at the PVT companies. Not recognizing this
early can cause difficult recovery delays in an unforgiving
project schedule. However to support these efforts, we are
increasingly requiring expertise, analysis details, and quick
cycle time from our own people and those at the companies
that provide PVT analysis. We must be able to differentiate
between what is a ‘have-to-have’ and what is a ‘nice-to-have’.
This generates confidence that our need for $100,000 worth of
fluid samples and $40,000 of analytical work can be translated
to a value for the asset (e.g. a $1,000,000 NPV is an estimated
seven days of production deferred to the end of the assets
lifecycle).
Transport & Process Management
Transport and process simulators provide the fundamental
information on which an asset design is built out. These
simulators via the asset’s depletion plan generate the global
pressure, temperature, and phase rates for the asset design
from the reservoir to export. Unfortunately until recently, a
number of independent simulators have been required to
design from reservoir to export. Typically simulations from
one discipline must be redone so that information for another
discipline can be recovered. Alternatively, assumptions are

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FLOW ASSURANCE: A π DISCIPLINE

made that do not necessarily coincide between disciplines.
Historically, interface management between the resevoir, the
well, the flow line, and the process simulations are
problematic. The response time to each disciplines request
and recovery recycle under increasing project cycle
compression compiles the interface management issue.
A common fluid characterization is an integrator that can
facilitate interface management between these disciplines.
Fundamental to the accuracy of the design simulators is their
description and numeric stability of the fluid model.
Validating the simulated fluid characteristics against
laboratory data, then tuning the fluid model to that data cannot
be over stated as a critical component to getting the simulator
results and thereby the asset design right for operations.
Another integrating capability is the appearance of simulators
that provide ‘one-stop-shopping’ for in-flow performance,
well flow, multi-phase flow line transport, and process
accurately within the same simulator. As these simulators by
necessity utilize and generate the data required for items such
as hydrate, wax, asphaltene, and scale formation / deposition,
we are finding increasing access to ‘one-stop-shopping’, flow
assurance simulation. These tools are multiphase transport
simulators by necessity. However, these simulators offer a
variety of correlations for in-flow performance, vertical flow,
horizontal flow, and process that can impact getting consistent
results at the discipline interfaces. It is important for the flow
assurance team to discuss, select, and utilize appropriate and
consistent correlations and fluid models across the asset
design.

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down and warm up of the well bore at production rates over
the wells lifecycle.
Transient simulation is replacing steady state simulation with
the advent of new tools that allow analysis of the volumes of
data generated by transient simulations. One of the most
significant advancements is the coupling of transient
multiphase simulators with process simulators. We now have
the capability to design and operate the console of the virtual
asset’s infrastructure before any infrastructure is built. We
can run operation scenarios that enhance an operators learning,
test the dynamic interaction of the system design, and allow
quick feedback to improve the designed system. In the near
future, new simulator modules will allow a wider range of
fluids and transport characteristics to be simulated. Examples
are multiphase transport of non-Newtonian fluids, composition
tracking, solids formation, solids deposition and solids
transport (e.g. wax, hydrates, scale, and sand).
The simulator challenges that face us are validation,
understanding, and utility. A simulator is only as good as the
data on which it was validated. It is important for the user to
understand what the simulator is doing, is not doing, and what
are the interface patches. We must recognize what flow
assurance issues and the contributing factors are long and
short term such as the difference between wax deposition, gel
generation, and slugging. The simulator must be configured to
assist with data configurability and avoid information
overload. Our understanding of the technology behind the
simulator, our ability to benchmark the results, and our
proficiency in the diverse sciences integrated in the simulator
impact how useful is the integrated simulator.

With these new tools, parametric studies can be done to
identify key parameters the will control the flexibility and
robustness of the infrastructure design. The inspectability of
these parametric matrices provide early learnings that can be
utilized as a design basis. The project can build flexibility and
quick response to issues that are difficult to quantify early.
The flow assurance matrix assists with understanding the
ramifications of early decisions on flow assurance solutions.
In-flow performance monitoring and identifying reasons for
possible degradation, well pressure decline, well warm up and
cool down for casing and operations design, water rates, water
chemistry, the onset point for continuous hydrate inhibition,
and slug control are a few examples.

Hydrate Management
Scientific knowledge of hydrates has significantly advanced in
the last ten years. Simulators predict the hydrate propensity
against the design options. We can predict hydrate
disassociation within one to three degrees with the exception
of brines that have high salt concentration. The hydrate
disassociation curves typically provide conservative limits for
hydrate management design. The effects of thermodynamic
hydrate inhibitors, THIs, such as methanol and ethylene
glycols can be predicted with acceptable accuracy. THIs are
used successfully for hydrate prevention, but can require up to
1 bbl of THI per bbl of water produced.

Is steady state or transient simulation required? This is a
perspective of the time scale relative to the impact or control
of the impact. Steady state simulations provide relatively,
simple results. Reservoir simulation does not require the same
time interval steps as riser slugging. However, pressure and
fluid front movement within the reservoir are important, but
on a longer time scale that slugging in a riser. Production
operations are never steady state. Transient changes in
process flow due to compressor control and vice-versa are
difficult to assess with steady state modeling. Well casing
integrity is facilitated with thermal transients during cool

As a result, methanol is used as the a primary hydrate inhibitor
in deep and shallow water. For projects producing oil in 2005
and beyond, there is talk of a 50-ppm to 100-ppm methanol
limit for sales oil quality. The issue of an oxygenated solvent
limit for glycols in oil is still under discussion. Methanol and
glycol recovery units today are incrementally improving the
basic technology. However, the units require appreciable heat
to recover the THI. Scaling in the methanol and glycol stills
can generate operations challenges, especially when the
produced water chemistry is not available from the reservoir
appraisal during the design phase. Glycol recovery units can

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be designed to remove the salts that have traditionally limited
the glycol quality. To reduce the methanol and glycol to the
needed oil quality target, crude washing requires large
volumes of water that must be treated to the seawater injection
quality. The recovery units and wash units have a significant
footprint, weight, and operability impact on the project and
operations design. These units are large and heavy. The units
are designed against one of the greatest unknowns in our
industry and projects, water rates and water chemistry.
So, how do we build flexibility into deepwater floaters?
How well do our PVT simulators predict the partitioning of
methanol and glycol between the water and hydrocarbon
phases? How well do our tools predict water chemistry
interaction with THIs? Do our recovery and washing designs
achieve the targets for the oil quality? Can the crude quality
targets be measured? These are all good questions. These
questions become less significant if we get rid of the need for
methanol and glycol. Several technologies can be considered
separately or in conjunction to minimize the use of THIs.
Before continuous hydrate inhibition is required, operation’s
procedures may be able to manage the use of THIs. Hydrate
inhibition may be equired before cool down and during warm
up. The production can be treated with THI prior to shut-in
and during startup if sufficient injection capacity can keep up
with the water rate. If possible, the subsea flow line can be
blown down and displaced with non-hdyrating fluid such as
sales oil or diesel. This of course takes time and must be done
before hydrate conditions are achieved in the subsea flow line.
Unplanned shut-ins can be an issue.
System design must always balance between extended cool
down times with short warm up times. Thermal management
can assist with maintaining some room for response by
assisting with adequate temperatures for both hydrate and
paraffin control. Both passive and active systems have been
utilized. Passive thermal management is by extended reach
drilling, insulation, and burial. Keeping production below the
mud line by extended reach drilling is one of the best thermal
management options. This may not always be feasible.
Insulation and burial can provide value when a subsea tieback
is necessary. With existing riser design constraints for near
future water depths, production risers may look more like
insulated flow lines. Pipe-in-pipe and bundled systems can
extend the production duration before continuous hydrate
inhibition is required. However, there may not be sufficient
thermal capacity to provide the necessary protection duration
for shut-ins greater than four to eight hours. Phase change
material insulation systems that provide heat ‘storage’ are
beginning to appear as commercial systems. Burial wtih six
inches are greater of soil above the pipe can provide extended
cool down times due to the thermal mass of the soil. Minimal
insulation is required to prevent excessive warmup times
during startup. However, buckling of a buried line can leave
sections of the pipeline exposed and susceptible to hydrate and
wax problems. Warm up time and cool down time can be

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optimized with insulation and thermal mass. Future
challenges for passive thermal management will be insulation
performance at high pressure, successfully installing dry pipein-pipe systems, keeping buried pipe buried, and developing
insulation with greater thermal capacity at a cost that can be
supported by the barrel of oils produced (BOEPs).
Actively heated systems provide the next level of thermal
management. Both electric and heating media systems have
been put in the water. Heating media systems require pipe-inpipe or bundle flow line designs for the needed flow area
required to the circulation rate of the heating media. When
design, installation, and corrosion management issues are
successful, heating media systems can be reliable. However,
the heat transported is still limited by the carrier insulation and
heat input at the platform. Electric ‘skin effect’ heating
systems have been used reliably for heat tracing of process
lines onshore. However, the existing on-shore systems have
heat and length limitations up to about 5 kV. Proposed and
installed subsea systems require high voltage, 15 kV,
capabilities on topsides and subsea connections. With
safeguards in-place to prevent possible shorting of the power
line to the production line, the efficiency of electric power to
heat power is between 25% and 30%. The magnetic
properties of the heated production line affect this efficiency.
Improvements to this efficiency are getting worked to enhance
the implementation of the technology. Active heating
systems, electric and heating media, can require in excess of 2
MW of duty from the topsides platform for greater than a four
mile subsea tieback. Integration of topsides and subsea design
details must be bought into and monitored to successfully
complete the implementation cycle from fabrication,
installation, to operations.
Low dosage hydrate inhibitors (LDHIs) fall into two
categories, kinetic (KIs) and anti-agglomerates (AAs). LDHIs
are making headway into operations use. Some of this usage
is driven by necessity due to implementation issues with some
of the newer technology. LDHIs offer some advantages to the
typical THIs (e.g. methanol and glycols) due to the lower
concentrations required. Anti-agglomerates are exhibiting
protection at higher subcoolings than kinetic hydrate
inhibitors. There are still challenges that are getting worked to
better understand the transport and kinetic nature of hydrates
and hydrate slurries with anti-agglomerates for ‘steady state’
multiphase flow, shut-in, startup, and processing. The kinetics
of hydrate formation and disassociation is getting worked to
better help us factor in residence time as a design factor for
hydrate management. However, low dosage hydrate inhibitors
are not recoverable and they are expensive. Typical use is for
hydrate protection during startup. LDHIs can have some
significant advantages for reducing chemical injection rates
and volumes relative to THIs. Unplanned, long term shut-ins
of startup opertions that use LDHI’s may inadvertently
provide additional information on the long term performance
of LDHIs. The challenge for hydrate management with
LDHIs will be developing the chemical performance

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FLOW ASSURANCE: A π DISCIPLINE

envelope, simulating the slurry transport and processing,
justifying the operating cost relative to a THI’s reliability,
operating cost, delivery, recovery stills, crude washing, and
supply.
Subsea processing offers promise for reducing the hydrate
inhibition requirements. Both three phase, gas/oil/water, and
two phase, gas/liquid, separation systems are in development.
Three-phase separation with water re-injection would be ideal.
Water quantity and therefore chemical concentrations would
be minimized if required at all. The amount of overboard
water disposal would be significantly reduced. However,
achieving injection quality water can be a challenge even on
topsides. Working over a deepwater injection well due to
injectivity degradation can be expensive.
Hydrate chemical requirements for the two-phase separation
process may be greater than three-phase separation, but
significantly reduced to that of non-seperated production. As
the gas stream only carries water of saturation it will require
minimal hydrate chemical similar to three-phase separation.
Depending on the separation pressure, the moles of hydrate
former in the ‘oil’ are significantly reduced relative to the nonseparated production. This generates reduced subcoolings. In
addition, the reduced ratio of moles of hydrate formers to the
moles of water in the liquids stream limits the volume of
hydrates in the liquid stream. However, the liquids pump on
subsea processing units require similar electric power and
integrity issues as subsea, electric heating systems.
In a well(s) life cycle, hydrate management will progress from
shut-in and startup operations to continuous inhibition. How
many equivalent barrels remain in the reservoir at this point?
The economic decision to consider is if these incremental
barrels at the end of the well lifecycle need to pay for the any
of the above hydrate management facilities with associate
reliability risks.
What are the remaining challenges for hydrate management?
Options must be available that are economically favorable to
topsides THI stills and crude washing. Simulation of THI
partitioning prediction and monitoring of ppm concentrations
of THI in crude must be validated. Validated simulation of
multiphase slurry transport and hydrate formation kinetics
with the use of LDHI’s must provide confidence that the flow
line can be restarted after shut-in. Insulation systems with low
heat transfer coefficients at a reduced thickness (e.g. one to
two inches) are needed. Reliable installations of pipe-in-pipe
systems that have heat transfer integrity over their entire
length are needed. With the extended shut-in times possible
with flow line burial, there must be a way to keep the flow line
economically buried. Long-term integrity or ROV
replacement of high voltage, electric power to subsea
processing and actively heated systems must be validated.
Low cost and quick replacement of subsea processing
components must be made available to minimize downtime
and redundant design for hydrate management.

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Paraffin Management
Paraffin deposition can be considered a steady state issue
relative to multiphase transport such as slugging. Simulation
and prediction of wax deposition has provided the industry
with fairly conservative estimations for remediation frequency
of risers and pipelines. Science has captured that the paraffin
fraction of the composition that must be measured via
specialized HTGC methods. In addition, the thermal gradient
and mass transfer at the pipe wall are recognized as the
mechanisms that drive deposition. This has allowed
appropriate thermal management design through the use of
widely available wax deposition simulators. However, one
must be cautioned that multiphase, wax deposition simulators
that also provide multiphase transport results should be based
on validated transport simulators.
The conservatism of the wax deposition predictions is getting
challenged. Operations are typically not experiencing wax
buildup at the pigging frequency predicted by the wax
deposition simulators. This conservatism, in part, drives
whether round trip pigging is required with the associated two
flow lines and manifold valving or if a reduced pigging
frequency supports a subsea pig launcher that can replace a
flow line or if activley heated systems can be considered as
viable option to no pigging. Chemical paraffin inhibitors can
assist with reducing the pigging frequency if they can be
injected at a point where the temperature is above the wax
appearance temperature over the lifecycle of the tieback.
One of the main challenges for paraffin management is
reliable and economic, one way pigging with a subsea pig
launcher. This includes the efficiency of the pigging operation
and the reliability of predicting the risk of sticking the pig in
the line. Generally, low heat transfer at the wall supports
porous wax deposits that are easier to pig than the dense
deposits resulting from large heat transfer gradients at the
wall. The low heat transfer option would be typical of
insulated flow lines.
Asphaltene Management
Asphaltenes are black, gummy, and slick. What is an
asphaltene is not scientifically, well defined. Precipitation
from the stock tank oil with various solvents having different
‘solubility parameters’ is the normal method of classification.
In the well bore, the onset of asphaltene precipitation for
unstable asphaltenic oils occurs above the saturation pressure.
A quick assessment of this asphaltene instability was
developed by deBoar and continues to be a first estimate that
is made possible using PVT data from a constant composition
expansion experiment. New high pressure, in-situ flocculation
experiments allow us to measure the flocculation pressure and
even ‘see’ the asphaltene particles within the crude. However,
the ability to simulate the fraction of asphaltenes deposited is
not available.
Asphaltene deposition occurs as the flocculation pressure
moves down the well bore tubing. Typically, asphaltene

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dispersant chemicals can be used successfully. However, the
chemical injection point must be at the reservoir depth. This
requires high-pressure injection at appreciable rates (e.g. 300
ppm in oil). Asphaltene inhibition is exceeded in injection
facililties, volume, and cost only by hydrate inhibition.

water till the deposition dissolves. Significant production
down time can occur. Injection of potable water downhole as
a ‘chemical’ might provide relief for deposition in the
wellbore. Water chemistry and aqueous simulation tools are
critical to this relief.

If an asset requires gas lift or commingles production down
hole and has asphaltenes, a careful study of the downhole fluid
interactions should be done. Chemical performance is one of
the only methods to prevent frequent asphaltene work overs.
Reservoir pressure maintenance above the flocculation
pressure could be considered. However, it is costly unless
pressure maintenance significantly enhances recover of
hydrocarbons in place.

The greatest challenge for scale technology is the availability
of quality water samples from appraisal or discovery wells
depending on the fast track nature of the asset development.
Recognition that drilling mud samples must be retained to
‘back out’ drilling mud contamination from the water
chemistry is generally captured too late. With water and mud
samples available, water chemistry can be prevent operations
challenges as the fundamentals for hydrates, scale, and
corrosion management can be built into the asset design basis.
Appreciating the value of advanced analytical techniques that
allow us to differentiate and quantify species such as organic
acids from the bicarbonates that are reported in standard water
chemistry analysis can have a significant impact on materials
selection and facilities integrity.
Quantification of the
‘salting’ out effect and aqueous chemistries with as much as
60 wt% ethylene glycol or methanol need additional validation
at low and high pressure with high Total Dissolved Solids
(TDS) brines.

Asphaltene deposition can become a more critical issue when
the flocculation pressure moves down the wellbore to the near
wellbore region as the reservoir pressure declines. At this
point, it is possible for asphaltenes to degrade a well’s inflow
performance. Remediation squeezes or soaks are the few
options available.
Differentiating asphaltenes or fines
migration or both, as degraders of in-flow performance must
be assessed carefully to select the appropriate remediation
process.
A high-pressure study with in-situ asphaltene precipitation and
deposition is our challenge. However, live reservoir fluids are
costly and volumes are limited even after first oil. Validating
premium chemical performance with limited oil samples
during the preliminary design is critical. This can reduce the
chemical injection requirements for asphaltene deposition in
the tubing. When the asphaltene flocculation pressure invades
the near well bore, our detection and remediation options can
be limited. Tests for gravel pack, screen, and/or reservoir core
plugging with asphaltene precipitation using live fluids are
difficult and problematic. Science is still the driver for
progress in asphaltene management.
Scale Management
Inorganic scale prediction is a mature, production technology.
It effects shallow water and deepwater equally. Science has
provided good simulation tools for predicting salt and scale
precipitation over a wide range of pressures and temperature.
Current studies are measuring the ‘aqueous’ chemistry and
partitioning in high concentration brines with ethylene glycol
and methanol. Experimental methods for evaluating the
performance of chemicals are available. Chemical companies
have a wide range of high performance scale inhibitors at low
concentrations. Scale squeezes are used with increasing
frequency after careful study of the chemical interactions with
reservoir sediments.
In deepwater Gulf of Mexico assets, the proximity of salt
domes increases the risk of having high, total dissolved solids
(TDS) production waters. Where the produced water is near
saturation, sodium chloride deposition can occur. There are
no chemicals for treating sodium chloride precipitation. The
only remediation method is washing with seawater or potable

Integrity Management
Facilities design and integrity monitoring is the ‘stuff’ from
which lifecycle, infrastructure integrity is built. Corrosivity
analysis from reservoir to sales point is fundamental.
Materials selection and appropriate welding practices must be
determined early in the project. The external and the internal
integrity of equipment and facilities must be measured.
Sand/silt/solids management must be implemented from
completions to topsides equipment. Chemical and fluid
capatibilities with seals must be addressed. Operations
integrity of utility fluid chemistry, compressors, pumps,
meters, and control systems must be addressed. Coupled
dynamic process and multiphase simulation can provide
virtual testing. Topsides layout needs to accommodate
remediation by coiled tubing for risers and subsea center SCRs
in addition to all the other equipment. Monitoring points must
be safely accessible during operations and be positioned to
monitor the information required. Alarm targets must be
identified. Data acquistion systems and databases must be
maintained to record and track trends. Data, trends, and
alarms must be monitored. Team and personnel integrity must
be maintained.
Integrity management requires front end loading the nth year of
operations into the conceptual design team. The operation’s
team meets the project design team in integrity management.
There is a wide variation in the industry as to when the
operation’s team meets the project design team. Within some
projects, the Operations Interface Manager (OIM) has a team
that is integrated into the project team. When this is the case,
the operation’s team typically becomes the project’s customer
for integrity and operability management.

OTC 14010

3

FLOW ASSURANCE: A π DISCIPLINE

Integrity management can also define the many issues
associated with interface management in an asset development
from project into operations. Some may view interface
management as a contractual issue. Valuing the proficiencies
of the organizations and people involved by their learned
expertise is critical. Knowledge is not proficiency. However,
objective reflection on what we know, what we think we
know, what our are our assumptions, and what we know we do
not know are important to valuing the organization and people
proficiencies involved.
Implementation Management
Maintaining the technological details throughout design,
execution, and operations is critical to providing flow
assurance. To do this, proficiencies from science to projects
to operations must be integrated. These proficiencies do not
reside in the same organization. Interface management that
maintains attention to details becomes critical. The flow
assurance discipline assist the management of these interfaces
by maintaining focus on the science and engineering realities
while maintaining operations as the customer.
We must always be diligent to recognize paradigms that exist.
Each application is unique from previous installations or
designs in more the one facet. Analysis of the what made the
previous installation work, what is different about the current
need, and what needed improvement or what do we not want
to repeat is an imperative process in implementation
management. We must work the paradigms even if on the
surface they seem unimportant.
The π3 strategy keeps the flow assurance discipline focused on
these issues. Proficiency is a key element of success that is
carried by people or people operating with an organization
structure. Integration of those profiencies is an organization
process that leads to success. Mutli-discipline teams have
proven very helpful in assisting with the integration process.
We need to extend them across the boundaries and facets of
science, projects, and operations. Implementation with
successful operation is our focus. Operations are our
customer. Improvement is a requirement to incorporate all
learnings into another successful installation. In carrying out a
π3 strategy, we commit ourselves to success.
Summary
Flow assurance is successful operations that generate a
reliable, manageable, and profitable flow of fluids from the
reservoir to the sales point. The flow assurance discipline that
enables these operations is an integration of disciplines, from
operations to engineering to business to science. It requires
the involvment of all the people involved in the value chain of
an asset from operations support to contractor to the scientist.
The flow assurance discipline drives a new perspective, a new
focus in our approach to reliable production operations. Its
vision goes from reservoir to sales, from concept design to
operations.

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This vision is slightly modified from a traditional vision that
views flow assurance as the study of production fluid issues.
Advancements in the study and simulation of production
technology have provided us with tools that can facilitate
successful designs. However, we must successfully execute
and operate those designs. This extension brings the flow
assurance discipline to the next stage of evolution. Doing so
requires more proficiencies to buy-in and claim ownership to
the discipline.
The π3 strategy helps to integrate the perspectives of a diverse
range of disciplines to implement a successful operating
solution. It can be of value if it facilitates that purpose. It is
designed to generate discussion and thought. It will transform
beyond itself if π3 proves to be of value.
Aknowledgement
I would like to thank Conoco, Inc. for permission to publish
this paper and for the opportunity to be exposed to a
worldwide community of people who enable the best to be
achieved.
Reference
1.Whitson, C.H., Brule, M.R., Phase Behavior, SPE Monograph, Vol.
20, 2000, Richardson, TX.